Method and system for real time gas turbine performance advisory

ABSTRACT

A system and method for monitoring and diagnosing anomalies in an output of a gas turbine, the method including storing a plurality rule sets specific to a performance of the gas turbine. The method further including receiving real-time and historical data inputs relating to parameters affecting the performance of the gas turbine, periodically determining current values of the parameters, comparing the initial values to respective ones of the current values, determining a degradation over time of the at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption based on the comparison, recommending to an operator of the gas turbine a set of corrective actions to correct the degradation.

FIELD OF THE INVENTION

This description relates to generally to mechanical/electrical equipment operations, monitoring and diagnostics, and more specifically, to systems and methods for automatically advising operators of anomalous behavior of machinery.

BACKGROUND OF THE INVENTION

Increasing the efficiency of gas turbines and optimizing their performance is a top priority for oil and gas manufacturers and customers. All gas turbines require routine maintenance at various intervals, for example, ranging from approximately every 6000 hours to approximately every two years. Many factors contribute to the performance degradation that necessitates such maintenance, such as those related to the axial compressor and hot gas path components. Axial compressor-related degradation may occur due to blade fouling and corrosion, and inlet filter pressure drop due to clogging. Foreign deposits that pass through inlet filters can accumulate on the compressor blades. This results in a drop of axial compressor efficiency and pressure ratio, which, in turn, results in an output performance drop such as a reduction in output power and thermal efficiency. This drop in output performance may be able to reach 5% within a month of operation. With the exception of blade corrosion and fatigue, most axial compressor-related problems can be reversed with routine maintenance. On-line and off-line water washing are used periodically to restore the machine operating condition. Similarly, replacing the inlet filter can reduce performance degradation due to filter clogging. Therefore, continuous monitoring of the machine to detect early signs of degradation facilitates prolonged shut down periods. Continuous monitoring also allows for performance optimization by adapting some of the process parameters, environmental conditions, or maintenance schedules.

Traditional performance monitoring systems use generic formulas and thermodynamic equations to calculate performance metrics. The specific design and control strategy for the monitored gas turbine are not accounted for. Expected performance is thus only theoretical and does not correspond to actual monitored machines. Many assumptions are used that result in significant errors. Hence, such systems cannot detect early signs of degradation. For example, a change in compressor efficiency of only 1-2% may indicate the need of a water wash. Correction factors are not used accurately to account for different control strategies. In addition, output performance rules are valid for full load conditions only. It is well known, however, that machines are routinely operated under part load conditions. Accordingly, such rules are not typically valid for all load ranges. Also, no link is provided between output and input parameters. Each component is monitored separately. Thus, troubleshooting is not facilitated. Another major drawback of known monitoring systems is that their rules depend on data from sensors that do not exist or are malfunctioning, resulting in rules that are inaccurate or obsolete.

SUMMARY OF THE INVENTION

In one embodiment, a computer-implemented method for monitoring and diagnosing anomalies in an output of a gas turbine wherein the method is implemented using a computer device coupled to a user interface and a memory device, and wherein the method includes storing a plurality rule sets in the memory device, the rule sets relative to the output of the gas turbine, the rule sets including at least one rule expressed as a relational expression of a real-time data output relative to a real-time data input, the relational expression being specific to at least one of a performance of a compressor of the gas turbine, a power output of the gas turbine, a heat rate of the gas turbine, and a fuel consumption of the gas turbine. The method further includes receiving real-time and historical data inputs from a condition monitoring system associated with the gas turbine, the data inputs relating to parameters affecting at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption, determining initial values of at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption, periodically determining current values of at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption, comparing the determined initial values to respective ones of the current values, determining a degradation over time of the at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption based on the comparison, and recommending to an operator of the gas turbine a set of corrective actions to correct the degradation.

In another embodiment, a gas turbine monitoring and diagnostic system for a gas turbine that includes an axial compressor and a low pressure turbine in flow communication includes a gas turbine performance rule set, the rule set including a relational expression of a real-time data output relative to at least one of a performance of a compressor of the gas turbine, a power output of the gas turbine, a heat rate of the gas turbine, and a fuel consumption of the gas turbine.

In yet another embodiment, one or more non-transitory computer-readable storage media has computer-executable instructions embodied thereon, wherein when executed by at least one processor, the computer-executable instructions cause the processor to store a plurality rule sets in the memory device wherein the rule sets are relative to the output of the gas turbine, the rule sets include at least one rule expressed as a relational expression of a real-time data output relative to a real-time data input, the relational expression being specific to at least one of a performance of a compressor of the gas turbine, a power output of the gas turbine, a heat rate of the gas turbine, and a fuel consumption of the gas turbine. The computer-executable instructions further cause the processor to receive real-time and historical data inputs from a condition monitoring system associated with the gas turbine, the data inputs relating to parameters affecting at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption, determine initial values of at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption, periodically determine current values of at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption, compare the determined initial values to respective ones of the current values, determine a degradation over time of the at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption based on the comparison, and recommend to an operator of the gas turbine a set of corrective actions to correct the degradation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1-8 show exemplary embodiments of the method and system described herein.

FIG. 1 is a schematic block diagram of a remote monitoring and diagnostic system in accordance with an exemplary embodiment of the present invention;

FIG. 2 is a block diagram of an exemplary embodiment of a network architecture of a local industrial plant monitoring and diagnostic system, such as a distributed control system (DCS);

FIG. 3 is a block diagram of an exemplary rule set that may be used with LMDS shown in FIG. 1;

FIG. 4 is a flow diagram of a method of determining an axial compressor efficiency and degradation in performance over time in accordance with an exemplary embodiment of the present disclosure;

FIG. 5 is a flow diagram of a method of determining an axial compressor flow and degradation in flow over time in accordance with an exemplary embodiment of the present disclosure;

FIG. 6 is a flow diagram of a method of determining an output power and degradation in power output over time in accordance with an exemplary embodiment of the present disclosure;

FIG. 7 is a flow diagram of a method of determining an output power and degradation in power output over time in accordance with an exemplary embodiment of the present disclosure; and

FIG. 8 is a flow diagram of a method of a rule set used in determining a gas turbine fuel consumption in accordance with an exemplary embodiment of the present disclosure.

Although specific features of various embodiments may be shown in some drawings and not in others, this is for convenience only. Any feature of any drawing may be referenced and/or claimed in combination with any feature of any other drawing.

DETAILED DESCRIPTION OF THE INVENTION

The following detailed description illustrates embodiments of the invention by way of example and not by way of limitation. It is contemplated that the invention has general application to analytical and methodical embodiments of monitoring equipment operation in industrial, commercial, and residential applications.

Correcting gas turbine output degradation is a constant goal of operators of machinery. However, output degradation is often the result of degradation of input parameters. The methods described herein facilitate identifying the root cause of this degradation. The methods are used to monitor in real time the whole machine and links components to each other. Troubleshooting flowcharts based on output and input conditions can then be constructed.

A real time thermodynamic simulation software is used to perform the methods and to improve accuracy of the assessments by taking into account the specific design parameters of the monitored gas turbine, and is not generic for all gas turbines. Thus, the results fit better actual output values. Second, the thermodynamic simulation software algorithms use empirical and statistical correlations to estimate unknown parameters or correction factors. For example, a temperature-independent specific heat ratio is not assumed when calculating the axial compressor efficiency as is commonly done. Rather, an empirical correlation is performed to find the temperature at which this ratio is evaluated. Inlet guide vane opening and speed change parameters are also corrected for. Rules that fit each control zone, whether the machine is controlled by speed or IGV opening based on how the gas turbine is controlled when loading or unloading.

The degradation algorithm considers the initial condition of the machine when first deploying the monitoring system and uses the initial condition as a reference, rather than using theoretical expected values as a reference that may or may not correspond to the monitored machine. Moreover, the methodology uses rules and algorithms that work at all load conditions and not only full load conditions. However, output degradation can only be evaluated at full load conditions, because power is input to the process as demanded by the driven equipment, and it makes no sense to monitor this value at partial load as the drop or increase in power may represent a change in demand and not performance degradation. On the other hand, the fuel consumption rule can be applied at full and part load conditions. The rules validate input data to ensure the associated sensors are working properly. Also, the calculated fuel flow may be used to validate the measured value and the calculated output power is used to determine whether the torquemeter is malfunctioning by performing a heat balance calculation, and by using a statistical correlation between the output power and certain input parameters.

Performance monitoring is important to increasing efficiency, reduce fuel costs, and predict fouling. The axial compressor is the main source for many gas turbine performance issues. Embodiments of the disclose described below monitor the axial compressor polytropic efficiency and flow efficiency and report degradation relative to initial reference conditions. The efficiency calculations use empirical correlations to evaluate the specific heat ratio. Also, corrections are made to account for the gas generator speed, ambient temperature, as well as the inlet guide vane opening. Flow calculations are also corrected to ISO and full speed conditions. This methodology provides accurate results and allows for degradation detection at an early stage. The methodology also monitors output performance; mainly output power and heat rate. Both are calculated at full load conditions and corrected to ISO conditions. Degradation is defined relative to initial reference conditions. Moreover, the methodology provides a fuel consumption rule that is also applicable at part load conditions. Fuel consumption is directly correlated to output power and, thus, provides an output performance monitoring even at part-load conditions.

An axial compressor performance rule-based monitoring module as part of an online gas turbine performance monitoring system includes:

1. Axial compressor efficiency and flow, which are two important parameters for characterizing the performance of an axial compressor in a gas turbine and can be used as a degradation indicator. The polytropic efficiency is referred to as small-stage efficiency and represents the isentropic efficiency of an elemental stage. In calculating this efficiency, the ratio of specific heats is calculated using an empirical correlation to capture the dependence on temperature. The calculated efficiency is then corrected for the actual axial compressor speed and inlet guide vane opening. The correction coefficients are obtained using a thermodynamic simulations software. This efficiency is monitored for degradation relative to the initial efficiency calculated at the first deployment of the monitoring system. Monitoring this value over time permits a prediction of the need for water washing or the presence of compressor fouling. The flow is proportional to the discharge pressure and depends on the ambient temperature and pressure. After correcting the ambient conditions to ISO conditions, the flow efficiency is also corrected based on the actual speed and inlet guide vane opening.

2. Output power and heat rate. The power output is either read from a torquemeter and, if not available, an energy balance is used to estimate it. A change in ambient conditions and both inlet and exit pressure losses are corrected for. These correction factors are obtained using thermodynamic simulations. The degradation of the corrected power or heat rate at base load conditions is monitored. The degradation factors are defined based on initial conditions similar to the definition of the axial compressor efficiency.

3. Fuel consumption: While the output rules apply at base load conditions, this rule can be applied at base load and part load conditions. Fuel consumption is the product of the fuel flow rate and the lower heating value of the fuel. Fuel consumption is a linear function of load at ISO conditions. The fuel flow is measured, the fuel flow and power are corrected to ISO conditions, and then the results are compared to the expected fuel consumption at ISO. The deviation in this case is the degradation parameter that can be monitored over time. If a reliable measurement of fuel flow is not available, the fuel flow is calculated using the choking condition on the gas control valve.

FIG. 1 is a schematic block diagram of remote monitoring and diagnostic system 100 in accordance with an exemplary embodiment of the present invention. In the exemplary embodiment, system 100 includes a remote monitoring and diagnostic center 102. Remote monitoring and diagnostic center 102 is operated by an entity, such as, an OEM of a plurality of equipment purchased and operated by a separate business entity, such as, an operating entity. In the exemplary embodiment, the OEM and operating entity enter into a support arrangement whereby the OEM provides services related to the purchased equipment to the operating entity. The operating entity may own and operate purchased equipment at a single site or multiple sites. Moreover, the OEM may enter into support arrangements with a plurality of operating entities, each operating their own single site or multiple sites. The multiple sites each may contain identical individual equipment or pluralities of identical sets of equipment, such as trains of equipment. Additionally, at least some of the equipment may be unique to a site or unique to all sites.

In the exemplary embodiment, a first site 104 includes one or more process analyzers 106, equipment monitoring systems 108, equipment local control centers 110, and/or monitoring and alarm panels 112 each configured to interface with respective equipment sensors and control equipment to effect control and operation of the respective equipment. The one or more process analyzers 106, equipment monitoring systems 108, equipment local control centers 110, and/or monitoring and alarm panels 112 are communicatively coupled to an intelligent monitoring and diagnostic system 114 through a network 116. Intelligent monitoring and diagnostic (IMAD) system 114 is further configured to communicate with other on-site systems (not shown in FIG. 1) and offsite systems, such as, but not limited to, remote monitoring and diagnostic center 102. In various embodiments, IMAD 114 is configured to communicate with remote monitoring and diagnostic center 102 using for example, a dedicated network 118, a wireless link 120, and the Internet 122.

Each of a plurality of other sites, for example, a second site 124 and an nth site 126 may be substantially similar to first site 104 although may or may not be exactly similar to first site 104.

FIG. 2 is a block diagram of an exemplary embodiment of a network architecture 200 of a local industrial plant monitoring and diagnostic system, such as a distributed control system (DCS) 201. The industrial plant may include a plurality of plant equipment, such as gas turbines, centrifugal compressors, gearboxes, generators, pumps, motors, fans, and process monitoring sensors that are coupled in flow communication through interconnecting piping, and coupled in signal communication with DCS 201 through one or more remote input/output (I/O) modules and interconnecting cabling and/or wireless communication. In the exemplary embodiment, the industrial plant includes DCS 201 including a network backbone 203. Network backbone 203 may be a hardwired data communication path fabricated from twisted pair cable, shielded coaxial cable or fiber optic cable, for example, or may be at least partially wireless. DCS 201 may also include a processor 205 that is communicatively coupled to the plant equipment, located at the industrial plant site or at remote locations, through network backbone 203. It is to be understood that any number of machines may be operatively connected to network backbone 203. A portion of the machines may be hardwired to network backbone 203, and another portion of the machines may be wirelessly coupled to backbone 203 via a wireless base station 207 that is communicatively coupled to DCS 201. Wireless base station 207 may be used to expand the effective communication range of DCS 201, such as with equipment or sensors located remotely from the industrial plant but, still interconnected to one or more systems within the industrial plant.

DCS 201 may be configured to receive and display operational parameters associated with a plurality of equipment, and to generate automatic control signals and receive manual control inputs for controlling the operation of the equipment of industrial plant. In the exemplary embodiment, DCS 201 may include a software code segment configured to control processor 205 to analyze data received at DCS 201 that allows for on-line monitoring and diagnosis of the industrial plant machines. Data may be collected from each machine, including gas turbines, centrifugal compressors, pumps and motors, associated process sensors, and local environmental sensors including, for example, vibration, seismic, temperature, pressure, current, voltage, ambient temperature and ambient humidity sensors. The data may be pre-processed by a local diagnostic module or a remote input/output module, or may transmitted to DCS 201 in raw form.

A local monitoring and diagnostic system (LMDS) 213 may be a separate add-on hardware device, such as, for example, a personal computer (PC), that communicates with DCS 201 and other control systems 209 and data sources through network backbone 203. LMDS 213 may also be embodied in a software program segment executing on DCS 201 and/or one or more of the other control systems 209. Accordingly, LMDS 213 may operate in a distributed manner, such that a portion of the software program segment executes on several processors concurrently. As such, LMDS 213 may be fully integrated into the operation of DCS 201 and other control systems 209. LMDS 213 analyzes data received by DCS 201, data sources, and other control systems 209 to determine an operational health of the machines and/or a process employing the machines using a global view of the industrial plant.

In the exemplary embodiment, network architecture 100 includes a server grade computer 202 and one or more client systems 203. Server grade computer 202 further includes a database server 206, an application server 208, a web server 210, a fax server 212, a directory server 214, and a mail server 216. Each of servers 206, 208, 210, 212, 214, and 216 may be embodied in software executing on server grade computer 202, or any combinations of servers 206, 208, 210, 212, 214, and 216 may be embodied alone or in combination on separate server grade computers coupled in a local area network (LAN) (not shown). A data storage unit 220 is coupled to server grade computer 202. In addition, a workstation 222, such as a system administrator's workstation, a user workstation, and/or a supervisor's workstation are coupled to network backbone 203. Alternatively, workstations 222 are coupled to network backbone 203 using an Internet link 226 or are connected through a wireless connection, such as, through wireless base station 207.

Each workstation 222 may be a personal computer having a web browser. Although the functions performed at the workstations typically are illustrated as being performed at respective workstations 222, such functions can be performed at one of many personal computers coupled to network backbone 203. Workstations 222 are described as being associated with separate exemplary functions only to facilitate an understanding of the different types of functions that can be performed by individuals having access to network backbone 203.

Server grade computer 202 is configured to be communicatively coupled to various individuals, including employees 228 and to third parties, e.g., service providers 230. The communication in the exemplary embodiment is illustrated as being performed using the Internet, however, any other wide area network (WAN) type communication can be utilized in other embodiments, i.e., the systems and processes are not limited to being practiced using the Internet.

In the exemplary embodiment, any authorized individual having a workstation 232 can access LMDS 213. At least one of the client systems may include a manager workstation 234 located at a remote location. Workstations 222 may be embodied on personal computers having a web browser. Also, workstations 222 are configured to communicate with server grade computer 202. Furthermore, fax server 212 communicates with remotely located client systems, including a client system 236 using a telephone link (not shown). Fax server 212 is configured to communicate with other client systems 228, 230, and 234, as well.

Computerized modeling and analysis tools of LMDS 213, as described below in more detail, may be stored in server 202 and can be accessed by a requester at any one of client systems 204. In one embodiment, client systems 204 are computers including a web browser, such that server grade computer 202 is accessible to client systems 204 using the Internet. Client systems 204 are interconnected to the Internet through many interfaces including a network, such as a local area network (LAN) or a wide area network (WAN), dial-in-connections, cable modems and special high-speed ISDN lines. Client systems 204 could be any device capable of interconnecting to the Internet including a web-based phone, personal digital assistant (PDA), or other web-based connectable equipment. Database server 206 is connected to a database 240 containing information about industrial plant 10, as described below in greater detail. In one embodiment, centralized database 240 is stored on server grade computer 202 and can be accessed by potential users at one of client systems 204 by logging onto server grade computer 202 through one of client systems 204. In an alternative embodiment, database 240 is stored remotely from server grade computer 202 and may be non-centralized.

Other industrial plant systems may provide data that is accessible to server grade computer 202 and/or client systems 204 through independent connections to network backbone 204. An interactive electronic tech manual server 242 services requests for machine data relating to a configuration of each machine. Such data may include operational capabilities, such as pump curves, motor horsepower rating, insulation class, and frame size, design parameters, such as dimensions, number of rotor bars or impeller blades, and machinery maintenance history, such as field alterations to the machine, as-found and as-left alignment measurements, and repairs implemented on the machine that do not return the machine to its original design condition.

A portable vibration monitor 244 may be intermittently coupled to LAN directly or through a computer input port such as ports included in workstations 222 or client systems 204. Typically, vibration data is collected in a route, collecting data from a predetermined list of machines on a periodic basis, for example, monthly or other periodicity. Vibration data may also be collected in conjunction with troubleshooting, maintenance, and commissioning activities. Further, vibration data may be collected continuously in a real-time or near real-time basis. Such data may provide a new baseline for algorithms of LMDS 213. Process data may similarly, be collected on a route basis or during troubleshooting, maintenance, and commissioning activities. Moreover, some process data may be collected continuously in a real-time or near real-time basis. Certain process parameters may not be permanently instrumented and a portable process data collector 245 may be used to collect process parameter data that can be downloaded to DCS 201 through workstation 222 so that it is accessible to LMDS 213. Other process parameter data, such as process fluid composition analyzers and pollution emission analyzers may be provided to DCS 201 through a plurality of on-line monitors 246.

Electrical power supplied to various machines or generated by generated by generators with the industrial plant may be monitored by a motor protection relay 248 associated with each machine. Typically, such relays 248 are located remotely from the monitored equipment in a motor control center (MCC) or in switchgear 250 supplying the machine. In addition, to protection relays 248, switchgear 250 may also include a supervisory control and data acquisition system (SCADA) that provides LMDS 213 with power supply or power delivery system (not shown) equipment located at the industrial plant, for example, in a switchyard, or remote transmission line breakers and line parameters.

FIG. 3 is a block diagram of an exemplary rule set 280 that may be used with LMDS 213 (shown in FIG. 1). Rule set 280 may be a combination of one or more custom rules, and a series of properties that define the behavior and state of the custom rules. The rules and properties may be bundled and stored in a format of an XML string, which may be encrypted based on a 25 character alphanumeric key when stored to a file. Rule set 280 is a modular knowledge cell that includes one or more inputs 282 and one or more outputs 284. Inputs 282 may be software ports that direct data from specific locations in LMDS 213 to rule set 280. For example, an input from a pump outboard vibration sensor may be transmitted to a hardware input termination in DCS 201. DCS 201 may sample the signal at that termination to receive the signal thereon. The signal may then be processed and stored at a location in a memory accessible and/or integral to DCS 201. A first input 286 of rule set 280 may be mapped to the location in memory such that the contents of the location in memory is available to rule set 280 as an input. Similarly, an output 288 may be mapped to another location in the memory accessible to DCS 201 or to another memory such that the location in memory contains the output 288 of rule set 280.

In the exemplary embodiment, rule set 280 includes one or more rules relating to monitoring and diagnosis of specific problems associated with equipment operating in an industrial plant, such as, for example, a gas reinjection plant, a liquid natural gas (LNG) plant, a power plant, a refinery, and a chemical processing facility. Although rule set 280 is described in terms of being used with an industrial plant, rule set 280 may be appropriately constructed to capture any knowledge and be used for determining solutions in any field. For example, rule set 280 may contain knowledge pertaining to economic behavior, financial activity, weather phenomenon, and design processes. Rule set 280 may then be used to determine solutions to problems in these fields. Rule set 280 includes knowledge from one or many sources, such that the knowledge is transmitted to any system where rule set 280 is applied. Knowledge is captured in the form of rules that relate outputs 284 to inputs 282 such that a specification of inputs 282 and outputs 284 allows rule set 280 to be applied to LMDS 213. Rule set 280 may include only rules specific to a specific plant asset and may be directed to only one possible problem associated with that specific plant asset. For example, rule set 280 may include only rules that are applicable to a motor or a motor/pump combination. Rule set 280 may only include rules that determine a health of the motor/pump combination using vibration data. Rule set 280 may also include rules that determine the health of the motor/pump combination using a suite of diagnostic tools that include, in addition to vibration analysis techniques, but may also include, for example, performance calculational tools and/or financial calculational tools for the motor/pump combination.

In operation, rule set 280 is created in a software developmental tool that prompts a user for relationships between inputs 282 and outputs 284. Inputs 282 may receive data representing, for example digital signals, analog signals, waveforms, processed signals, manually entered and/or configuration parameters, and outputs from other rule sets. Rules within rule set 280 may include logical rules, numerical algorithms, application of waveform and signal processing techniques, expert system and artificial intelligence algorithms, statistical tools, and any other expression that may relate outputs 284 to inputs 282. Outputs 284 may be mapped to respective locations in the memory that are reserved and configured to receive each output 284. LMDS 213 and DCS 201 may then use the locations in memory to accomplish any monitoring and/or control functions LMDS 213 and DCS 201 may be programmed to perform. The rules of rule set 280 operate independently of LMDS 213 and DCS 201, although inputs 282 may be supplied to rule set 280 and outputs 284 may be supplied to rule set 280, directly or indirectly through intervening devices.

During creation of rule set 280, a human expert in the field divulges knowledge of the field particular to a specific asset using a development tool by programming one or more rules. The rules are created by generating expressions of relationship between outputs 284 and inputs 282. Operands may be selected from a library of operands, using graphical methods, for example, using drag and drop on a graphical user interface built into the development tool. A graphical representation of an operand may be selected from a library portion of a screen display (not shown) and dragged and dropped into a rule creation portion. Relationships between input 282 and operands are arranged in a logical display fashion and the user is prompted for values, such as, constants, when appropriate based on specific operands and specific ones of inputs 282 that are selected. As many rules that are needed to capture the knowledge of the expert are created. Accordingly, rule set 280 may include a robust set of diagnostic and/or monitoring rules or a relatively less robust set of diagnostic and/or monitoring rules based on a customer's requirements and a state of the art in the particular field of rule set 280. The development tool provides resources for testing rule set 280 during the development to ensure various combinations and values of inputs 282 produce expected outputs at outputs 284.

As described below, rule sets are defined to assess the performance of axial compressor efficiency, axial compressor efficiency flow, gas turbine power output, and gas turbine heat rate. The measurements used in the determination include ambient temperature and pressure, GT axial compressor inlet temperature and pressure, GT axial compressor discharge temperature and pressure, GT inlet losses, GT axial compressor speed (TNH) and GT power turbine speed (TNL), power output (from torquemeter or driven compressor thermodynamic balance), and fuel flow and fuel composition.

FIG. 4 is a flow diagram of a method 400 of determining an axial compressor efficiency and degradation in performance over time in accordance with an exemplary embodiment of the present disclosure. In the exemplary embodiment, method 400 includes determining that the gas turbine is at steady state 402 and that the inlet guide vanes position is greater than 55% open 404. Temperatures T₂ and T₃ are read 406 from the monitoring system. Given the measured T₃, evaluate 408 the ambient corrected T₃corr as:

T _(3corr) =T ₃ +f _(T3)(T ₂),

where f_(T3)(T₂) is the correction based on ambient temperature, defined 410 as:

f _(T3)(T ₂)=c ₀ +c ₁(T ₂)_(° F.) +c ₂(T ₂)_(° F.) ² +c ₃(T ₂)_(° F.) ³,

where c₀ . . . c₃ are constants and T_(3corr) is the temperature at which the ratio of specific heats γ is evaluated 412:

${{{\gamma \left( \text{?} \right)} = {c_{0} + {{c_{1}\left( \frac{\text{?}}{\text{?}} \right)}\text{?}} + {{c_{2}\left( \frac{\text{?}}{\text{?}} \right)}\text{?}} + {\text{?}\left( \frac{\text{?}}{\text{?}} \right)\text{?}}}},{\text{?}\text{indicates text missing or illegible when filed}}}\mspace{346mu}$

where c₀ . . . c₃ are different constants then above.

Polytropic efficiency is evaluated as 414:

$\eta = {\frac{{\gamma \left( \text{?} \right)} - 1}{\gamma \left( \text{?} \right)}*\frac{{\ln \left( \frac{\text{?}}{P_{2}} \right)}\text{?}}{{\ln \left( \frac{\text{?}}{T_{2}} \right)}\text{?}}*{K_{1}\left( {T_{amb},{THN}} \right)}*{K_{2}\left( {T_{amb},{IGV}} \right)}}$ ?indicates text missing or illegible when filed                    

Further corrections are applied in order to estimate efficiency in the ranges: 94%<GT axial compressor speed (TNH)<100% and 56°<IGV<85°.

From base load (Temperature control, TNH=100%, IGV=85) downward, the control is operated by acting on TNH (from 100% to 94%) and keeping constant the IGV at 85°.

Ambient temperature corrected TNH correlation (K₁) is from 5° F. to 140° F.:

T_(amb) parameter is normalized as:

$\text{?} = {\left( \frac{T_{amb}}{\text{?}} \right)\text{?}}$ ?indicates text missing or illegible when filed                    

TNH parameter is between 0.94 and 1.

When TNH reaches 94%, further load decreasing is obtained by reducing IGV aperture (from 85° to 56°) and keeping constant the THN at 94%.

Ambient temperature corrected IGV correlation (K₂) is from 5° F. to 140° F.:

T_(amb) parameter is normalized as:

$\text{?} = {\left( \frac{T_{amb}}{\text{?}} \right)\text{?}}$ ?indicates text missing or illegible when filed                    

IGV parameter is normalized as:

${IGV}_{param} = \frac{IGV}{85}$

Method 400 includes correcting 416 η using K1 and K2, buffering 418 values and determining 420 an average efficiency. The degradation in compressor efficiency is determined 422 using:

${Degradation} = {\left( {1 - \frac{\text{?}}{FirstTimeEff}} \right)*100}$ ?indicates text missing or illegible when filed                    

FIG. 5 is a flow diagram of a method 500 of determining an axial compressor flow and degradation in flow over time in accordance with an exemplary embodiment of the present disclosure.

The general formula of flow estimation is:

$W_{2} = {\text{?}\frac{\sqrt{\left( \frac{T_{amb}}{518.67} \right)\text{?}}}{\left( \frac{\text{?}}{14.6959} \right)\text{?}}*{K_{1}\left( {T_{amb},{TNH}} \right)}*{K_{2}\left( {T_{amb},{IGV}} \right)}}$ ?indicates text missing or illegible when filed                    

In the exemplary embodiment, method 500 includes determining that the gas turbine is at steady state 502 and that the inlet guide vanes position is greater than 55% open 504.

Method 500 includes reading 506 T2 in ° K., P2, and compressor discharge pressure (CDP) in absolute pressure units. A flow coefficient is determined 508 from:

${{Flow}\mspace{14mu} {Coefficient}} = {{CDP}*\frac{\text{?}}{\text{?}}}$ ?indicates text missing or illegible when filed                    

The flow coefficient is corrected 510 using the ambient temperature corrected TNH correlation K₁ and the ambient temperature corrected IGV correlation K₂:

Flow Coefficient_(Corrected)=Flow Coefficient*K1*K2

Method 500 includes buffering 512 values and determining 514 an average flow efficiency. The degradation in flow efficiency is determined 516 using:

${Degradation} = {\left( {1 - \frac{\text{?}}{FirstTimeCoeff}} \right)*100}$ ?indicates text missing or illegible when filed                    

FIG. 6 is a flow diagram of a method 600 of determining an output power and degradation in power output over time in accordance with an exemplary embodiment of the present disclosure. In the exemplary embodiment, method 600 includes determining that the gas turbine is at steady state 602, that the inlet guide vanes position 604 is greater than 84% open, and that GT axial compressor speed (TNH) 606 is greater than 98%.

Values are read 608 for Pamb in units of psi, Tamb in units of ° F., ΔP inlet in mm H2O, RH (humidity) in units of percent, and TNL in units of percent. Correction factors are calculated 610 using:

K(Pamb)*K(RH)*K*(ΔP inlet)*K(Tamb, TNL)

Power output is read 612 from one of more of a torque meter, a heat balance, or from absorbed power from a centrifugal compressor plus losses and a corrected power output is determined 614 using:

Output Power Corrected=Output Power/Correction Factors

-   -   Degradation of the output power over time is determined 616         using:

${Degradation} = {\left( {1 - \frac{\text{?}}{\text{?}}} \right)*100}$ ?indicates text missing or illegible when filed                    

FIG. 7 is a flow diagram of a method 700 of determining an output power and degradation in power output over time in accordance with an exemplary embodiment of the present disclosure. In the exemplary embodiment, method 700 includes determining that the gas turbine is at steady state 702, that the inlet guide vanes position 704 is greater than 84% open, and that GT axial compressor speed (TNH) 706 is greater than 98%.

Values are read 708 for Pamb in units of psi, Tamb in units of ° F., ΔP inlet in mm H2O, RH (humidity) in units of percent, and TNL in units of percent. Correction factors are calculated 710 using:

K(Pamb)*K(RH)*K*(ΔP inlet)*K(Tamb, TNL)

-   -   A heat rate is determined 712 using:

(Fuel Flow*LHV)/(Out Power)

-   -   A corrected heat rate is determined 714 using:

Heat Rate Corrected=Heat Rate/Correction Factors

-   -   Degradation of the output power over time is determined 716         using:

${Degradation} = {\left( {1 + \frac{\text{?}}{\text{?}}} \right)*100}$ ?indicates text missing or illegible when filed                    

FIG. 8 is a flow diagram of a method 800 of a rule set used in determining a gas turbine fuel consumption in accordance with an exemplary embodiment of the present disclosure. In the exemplary embodiment, method 800 includes determining that the gas turbine is at steady state 802. If yes, method 800 includes receiving 804 a measured fuel flow from, for example, a fuel meter and a calculated fuel rate from a fuel rate calculation and determining 806 that the measured and the calculated are within 10% of the calculated value with respect to each other using:

abs(Measured−Calculated)/Calculated<10%

If yes 808, the measured fuel flow is used below. If no 810, the calculated fuel flow is used below. A fuel consumption correction is determined using:

Fuel Consumption Corrections=Fuel Flow*LHV/Correction Factors

The correction factors are determined from values read 814 for Pamb in units of psi, Tamb in units of ° F., ΔP inlet in mm H2O, RH (humidity) in units of percent, TNL in units of percent, and power output in units of kilowatts (kW). Correction factors are calculated 816 using:

K(Pamb)*K(RH)*K*(ΔP inlet)*K(Tamb, TNL, Output Power)

The fuel consumption correction at isometric power is determined 818 using:

Fuel Consumption Correction at ISO Power=Fuel Consumption Correction/Power Correction

The power correction ratio determined from a calculated expected isometric fuel consumption at current power 820 and a calculated expected isometric fuel consumption at ISO power 822.

The fuel consumption correction at isometric power is buffered 826 for a predetermined period, for example, but not limited to, sixty minutes to determine 828 an actual isometric fuel consumption. The calculated expected isometric fuel consumption at ISO power 822 is also buffered 830 for a predetermined period and the expected isometric fuel consumption is determined 832. A fuel consumption deviation is determined 834 using:

Deviation=(actual isometric fuel consumption 828)−(expected isometric fuel consumption 832)

The logic flows depicted in the figures do not require the particular order shown, or sequential order, to achieve desirable results. In addition, other steps may be provided, or steps may be eliminated, from the described flows, and other components may be added to, or removed from, the described systems. Accordingly, other embodiments are within the scope of the following claims.

It will be appreciated that the above embodiments that have been described in particular detail are merely example or possible embodiments, and that there are many other combinations, additions, or alternatives that may be included.

Also, the particular naming of the components, capitalization of terms, the attributes, data structures, or any other programming or structural aspect is not mandatory or significant, and the mechanisms that implement the invention or its features may have different names, formats, or protocols. Further, the system may be implemented via a combination of hardware and software, as described, or entirely in hardware elements. Also, the particular division of functionality between the various system components described herein is merely one example, and not mandatory; functions performed by a single system component may instead be performed by multiple components, and functions performed by multiple components may instead performed by a single component.

Some portions of above description present features in terms of algorithms and symbolic representations of operations on information. These algorithmic descriptions and representations may be used by those skilled in the data processing arts to most effectively convey the substance of their work to others skilled in the art. These operations, while described functionally or logically, are understood to be implemented by computer programs. Furthermore, it has also proven convenient at times, to refer to these arrangements of operations as modules or by functional names, without loss of generality.

Unless specifically stated otherwise as apparent from the above discussion, it is appreciated that throughout the description, discussions utilizing terms such as “processing” or “computing” or “calculating” or “determining” or “displaying” or “providing” or the like, refer to the action and processes of a computer system, or similar electronic computing device, that manipulates and transforms data represented as physical (electronic) quantities within the computer system memories or registers or other such information storage, transmission or display devices.

While the disclosure has been described in terms of various specific embodiments, it will be recognized that the disclosure can be practiced with modification within the spirit and scope of the claims.

The term processor, as used herein, refers to central processing units, microprocessors, microcontrollers, reduced instruction set circuits (RISC), application specific integrated circuits (ASIC), logic circuits, and any other circuit or processor capable of executing the functions described herein.

As used herein, the terms “software” and “firmware” are interchangeable, and include any computer program stored in memory for execution by processor 205, including RAM memory, ROM memory, EPROM memory, EEPROM memory, and non-volatile RAM (NVRAM) memory. The above memory types are exemplary only, and are thus not limiting as to the types of memory usable for storage of a computer program.

As will be appreciated based on the foregoing specification, the above-described embodiments of the disclosure may be implemented using computer programming or engineering techniques including computer software, firmware, hardware or any combination or subset thereof, wherein the technical effect includes (a) storing a plurality rule sets in the memory device, the rule sets relative to the output of the gas turbine, the rule sets including at least one rule expressed as a relational expression of a real-time data output relative to a real-time data input, the relational expression being specific to at least one of a performance of a compressor of the gas turbine, a power output of the gas turbine, a heat rate of the gas turbine, and a fuel consumption of the gas turbine (b) receiving real-time and historical data inputs from a condition monitoring system associated with the gas turbine, the data inputs relating to parameters affecting at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption, (c) determining initial values of at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption, (d) periodically determining current values of at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption, (e) comparing the determined initial values to respective ones of the current values, (f) determining a degradation over time of the at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption based on the comparison, (g) recommending to an operator of the gas turbine a set of corrective actions to correct the degradation, (h) determining unknown or unsensed parameters and correction factors using a thermodynamic simulation algorithm, (i) verifying an operability of sensors providing the real-time data inputs using at least one of the historical data inputs and the thermodynamic simulation algorithm, (j) determining a axial compressor efficiency using a temperature dependent specific heat ratio, (k) determining a temperature at which the ratio is evaluated using an empirical correlation, (l) monitoring the axial compressor polytropic efficiency and flow efficiency, (m) correcting the determined efficiency for an actual speed of the axial compressor and an actual opening of an inlet guide vane, (n) determining correction coefficients using a thermodynamic simulation, (o) correcting ambient conditions to isometric conditions, (p) correcting the flow efficiency based on the actual axial compressor speed and the inlet guide vane opening, (q) receiving a power output signal from a torquemeter, (r) determining the power output using an energy balance algorithm to generate a calculate power output signal, (s) determining values of the fuel consumption using a fuel flow rate and a lower heating value of the fuel, and (t) determining values of the fuel consumption at least one of full load and partial load. Any such resulting program, having computer-readable code means, may be embodied or provided within one or more computer-readable media, thereby making a computer program product, i.e., an article of manufacture, according to the discussed embodiments of the disclosure. The computer readable media may be, for example, but is not limited to, a fixed (hard) drive, diskette, optical disk, magnetic tape, semiconductor memory such as read-only memory (ROM), and/or any transmitting/receiving medium such as the Internet or other communication network or link. The article of manufacture containing the computer code may be made and/or used by executing the code directly from one medium, by copying the code from one medium to another medium, or by transmitting the code over a network.

Many of the functional units described in this specification have been labeled as modules, in order to more particularly emphasize their implementation independence. For example, a module may be implemented as a hardware circuit comprising custom very large scale integration (“VLSI”) circuits or gate arrays, off-the-shelf semiconductors such as logic chips, transistors, or other discrete components. A module may also be implemented in programmable hardware devices such as field programmable gate arrays (FPGAs), programmable array logic, programmable logic devices (PLDs) or the like.

Modules may also be implemented in software for execution by various types of processors. An identified module of executable code may, for instance, comprise one or more physical or logical blocks of computer instructions, which may, for instance, be organized as an object, procedure, or function. Nevertheless, the executables of an identified module need not be physically located together, but may comprise disparate instructions stored in different locations which, when joined logically together, comprise the module and achieve the stated purpose for the module.

A module of executable code may be a single instruction, or many instructions, and may even be distributed over several different code segments, among different programs, and across several memory devices. Similarly, operational data may be identified and illustrated herein within modules, and may be embodied in any suitable form and organized within any suitable type of data structure. The operational data may be collected as a single data set, or may be distributed over different locations including over different storage devices, and may exist, at least partially, merely as electronic signals on a system or network.

The above-described embodiments of a method and online gas turbine performance monitoring system that includes a rule module provides a cost-effective and reliable means for providing meaningful operational recommendations and troubleshooting actions. Moreover, the system is more accurate and less prone to false alarms. More specifically, the methods and systems described herein can predict component failure at a much earlier stage than known systems to facilitate significantly reducing outage time and preventing trips. In addition, the above-described methods and systems facilitate predicting anomalies at an early stage enabling site personnel to prepare and plan for a shutdown of the equipment. As a result, the methods and systems described herein facilitate operating gas turbines and other equipment in a cost-effective and reliable manner.

This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the disclosure is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. 

What is claimed is:
 1. A computer-implemented method for monitoring and diagnosing anomalies in an output of a gas turbine, the method implemented using a computer device coupled to a user interface and a memory device, the method comprising: storing a plurality rule sets in a memory device, the rule sets relative to the output of the gas turbine, the rule sets comprising at least one rule expressed as a relational expression of a real-time data output relative to a real-time data input, the relational expression being specific to at least one of a performance of a compressor of the gas turbine, a power output of the gas turbine, a heat rate of the gas turbine, and a fuel consumption of the gas turbine; receiving real-time and historical data inputs from a condition monitoring system associated with the gas turbine, the data inputs relating to parameters affecting at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption; determining initial values of at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption; periodically determining current values of at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption; comparing the determined initial values to respective ones of the current values; determining a degradation over time of the at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption based on the comparison; and recommending to an operator of the gas turbine a set of corrective actions to correct the degradation.
 2. The method of claim 1, further comprising determining a axial compressor efficiency using a temperature dependent specific heat ratio.
 3. The method of claim 1, further comprising correcting the determined efficiency for an actual speed of the axial compressor and an actual opening of an inlet guide vane.
 4. The method of claim 1, wherein determining values of the power output comprises at least one of receiving a power output signal from a torquemeter and determining the power output using an energy balance algorithm to generate a calculate power output signal.
 5. The method of claim 1, wherein determining values of the fuel consumption comprises determining values of the fuel consumption at least one of full load and partial load.
 6. A gas turbine monitoring and diagnostic system for a gas turbine comprising an axial compressor and a low pressure turbine in flow communication, said gas turbine monitoring and diagnostic system comprising: a gas turbine performance rule set, the rule set comprising a relational expression of a real-time data output relative to at least one of a performance of a compressor of the gas turbine, a power output of the gas turbine, a heat rate of the gas turbine, and a fuel consumption of the gas turbine.
 7. The system of claim 6, wherein said rule set is configured to: receive real-time and historical data inputs from a condition monitoring system associated with the gas turbine, the data inputs relating to parameters affecting at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption; and determine initial values of at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption; periodically determine current values of at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption; compare the determined initial values to respective ones of the current values; determine a degradation over time of the at least one of the performance of the compressor, the power output, the heat rate, and the fuel consumption based on the comparison; recommend to an operator of the gas turbine a set of corrective actions to correct the degradation.
 8. The system of claim 6, wherein the rule set is configured to verify an operability of sensors providing the real-time data inputs using at least one of the historical data inputs and a thermodynamic simulation algorithm.
 9. The system of claim 6, wherein the rule set is configured to determine an axial compressor efficiency using a temperature dependent specific heat ratio.
 10. The system of claim 6, wherein the rule set is configured to determine a temperature at which the ratio is evaluated using an empirical correlation. 